1. Field of the Disclosure
The disclosure relates to artificial lift production systems and methods deployed in subterranean oil and gas wells, and more particularly relates to systems and methods for separating gas and solids from reservoir fluids in vertical, deviated, or horizontal wellbores.
2. Description of the Related Art
Many oil and gas wells will experience liquid loading at some point in their productive lives due to the reservoir's inability to provide sufficient energy to carry wellbore liquids to the surface. The liquids that accumulate in the wellbore may cause the well to cease flowing or flow at a reduced rate because of the back-pressure exerted by the liquids on the reservoir. Flow from the reservoir is determined by the differential pressure between the reservoir and the surface facilities. Typically, a higher pressure differential equates to a higher production rate from the well. To increase or re-establish the production, operators may introduce additional energy to the wellbore, known as artificial lift, to increase the lifting of the liquids to the surface.
Several methods of artificial lift are known to the oil and gas industry, and artificial lift selection is often determined by the efficiency of a particular artificial lift method in handling gas and solids in conjunction with conventional down-hole gas and solids separation equipment. It is well known to persons of ordinary skill in the art that gas and solids in reservoir fluids, after entering the wellbore, may be detrimental to down-hole pumping systems. Both solids and gases may cause inefficiencies and failures in the down-hole equipment. Higher production rates have higher fluid velocities than lower production rates in similar-sized wellbores. When fluid velocities are high, there is a tendency to carry gas bubbles and solids along with the liquids into the conventional gas separation devices, which, in turn, allows the gas bubbles and solids to enter into the intake of the down-hole pumps. Conventional gas separation and solids removal systems are inadequate for higher production rates in a large number of wellbores as explained herein.
A common form of artificial lift is a sucker rod pump, and a common form of a down-hole gas and solids separation device is provided by a “poor boy separator”. This device has a concentric tubing arrangement consisting of an outer joint of tubing with a closed lower end and openings on the upper end. The outer tubing contains an inner tubing segment called a “dip tube” that serves to separate gas from the liquids and, also, as a conduit for the separated liquids to enter into the intake of the pump. A region called the “mud anchor” is formed between the terminus of the dip tube and the bottom of the outer tubular. The mud anchor allows for solids to settle within the separator.
The sucker rod pump cycle consists of an upstroke and a down-stroke. Most rod pumps are designed to lift liquids on the upstroke, whereas during the down-stroke, the pump plunger is merely lowered and fills a chamber with liquids without any significant fluid displacement that could result in a liquid velocity within the down-hole separator. During the upstroke, gas and liquids are drawn from the casing annulus into the upper openings in the outer tubular of the separator since the velocity induced by the pump exceeds the velocity of the gas bubbles rising in the reservoir fluids in the casing annulus. The liquids and gas bubbles travel down the annulus between the dip tube and outer tubing. During the down-stroke of the pump, as described previously, there is no liquid velocity in the separator, hence there is time for the gas to rise up and out of the separator through the openings in the upper end of the separator. Any gas bubbles that remain in the separator when the velocity begins to increase during the pump's upstroke will eventually be drawn into the intake of the pump, regardless of the length of the separator. The conventional separator size, and therefore capacity, is often limited by the casing size from reaching the maximum capacity limit of the production pump. In other words, the well casing size subsequently causes a reduction in the size of the outer tubular of the separator and the dip tube.
The sufficiency of the velocity of the liquids to draw gas down to the end of the dip tube is determined by the cross-sectional area of the annulus between the inner and outer tubulars of the separator and the production rate of the pump. When gas is drawn down to the lower end of the dip tube, the gas can enter the pump intake, which will reduce the efficiency of the pump.
A limitation of many poor boy separators is that these separators provide high liquid velocities due to limited cross-sectional area of the separator. This cross-sectional area is limited, in part, by the fact that the outer tubular of the separator must fit inside of the casing of the wellbore.
For example, a typical separator used in a 4½ inch (11.43 cm) casing within a wellbore has an outer tubular diameter of 2⅜ inches (6.02 cm) with a dip tube diameter of 1.66 inches (4.22 cm), as would be understood by a person of ordinary skill in the art. The inner and outer diameter of 2⅜ inch tubing (6.02 cm) is 1.995 inches (5.07 cm) and 2.375 inches (6.02 cm), respectively, and the inner and outer diameter of 1.66 inch tubing (4.22 cm) is 1.38 inches (3.51 cm) and 1.66 inches (4.22 cm), respectively. Published studies have shown that a majority of gas bubbles will continue to rise in salt water below velocities of 6 inches per second (15.24 cm per second). At fluid velocities of 6 inches per second (15.24 cm per second), the referenced separator can move approximately 52 barrels of liquid per day (8.27 cubic meters per day) before gas will be drawn into the intake of the pump. Another common size of separator is 2⅞ inches (7.3 cm) by 1.66 inches (4.22 cm) that has a limit of approximately 132 barrels of liquid per day (21 cubic meters per day) before gas will be drawn into the pump intake at a fluid velocity of 6 inches per second (15.24 cm per second). The inner and outer diameter of the 2⅞ inch tubing (7.3 cm) is 2.441 inches (6.22 cm) and 2.875 inches (7.3 cm), respectively.
Designing the outer tubular of the separator with a larger inner diameter is one way to increase the cross-sectional area of the separator, and, thus, lower the fluid velocity inside the separator; however, if the wall thickness of the separator is too thin, the structural integrity of the separator will be compromised. If both the inner and outer diameter of the separator are increased, then the cross-sectional area of the annulus between the separator and the casing wall decreases, which may restrict flow and induce back-pressure in the wellbore below the separator. The back-pressure will reduce the flow rate from the reservoir and defeat the purpose of using a larger diameter separator to increase the overall production rate. Furthermore, small tolerances between the separator and the casing wall may allow the accumulation of solids in or about the gap between the separator and the casing wall, and this accumulation may stick the separator in place. Reducing the outer diameter of the dip tube will also increase the cross-sectional area; however, a smaller inside diameter dip tube will also increase the friction of the liquids feeding the pump intake, which can starve the pump for liquids and increase the risk of plugging the dip tube with scale or solids.
Wells with small casing or liner sizes limit the application of conventional down-hole pumps, and the conventional down-hole gas separation equipment necessarily has to be smaller to accommodate the smaller casing and liner sizes. Many operators are currently drilling wells with smaller casing sizes in order to lower the upfront costs of drilling and completion. However, these operators still desire production rates well in excess of what conventional down-hole separators can deliver. Also, the higher fluid velocity in the separator that makes gas separation difficult also affects solids separation. There have been several attempts with various separator designs to lower the velocity of the liquid inside the separator. These designs have had varying degrees of success but yet still have limited production rates below the desires of operators. Similarly, attempts to separate out solids in the wellbore have proven to be inadequate.
A main operational concern for many pumps such as rod pumps, ESPs, and piston pumps is the presence of gas in the pumps. Since gas is highly compressible compared to liquids, these types of pumps operate efficiently only when gas is not present in the pump chamber. The presence of the gas may reduce lubrication, increase friction, allow heat build-up, increase cavitation, and increase vibration of the pump. All of these complications may reduce pump efficiency or cause the pump to fail. Reduced life expectancy of the pump due to the presence of gas in the pump can result in costly and time consuming repairs and/or replacement of the pump.
The presence of gas in the pumps can also cause the pumps to experience “gas lock”, which occurs when there is an insufficient amount of liquid near the intake of the pump. During operation of the pump, gas within the pump chamber may expand and compress due to the action of the pump and the change in volume of the pump chamber. The outflow of gas being compressed may prevent or limit liquids form entering the pump until the gas is expelled from the pump chamber. Therefore it is important that the intakes of the down-hole pumps be placed in liquids and down-hole separation equipment be designed to keep gas from entering the pump; otherwise, the efficiency of the pump is reduced.
One of the main limiting factors of conventional rod pump lift design is the use of a tubing anchor. In general, rod pumps require the production tubing to be anchored to prevent movement of the tubing that is induced by the motion of the rods, pump, and fluids in the production tubing string. Tubing anchors are mechanical devices that connect the tubing to the casing wall by a set of slips, similar to the way a packer operates, but without the sealing elastomers of a packer. Instead of sealing, the tubing anchors allow gas and liquids to flow around the tubing anchor so that the gas may flow to the surface and by-pass entering the intake to the pump. Movement of the production tubing can cause frictional contact between the production tubing and the casing, which may result in a down-hole failure in the tubing and/or the casing. Movement of the production tubing string may also cause the pump to lose efficiency since the movement of the tubing string with respect to the plunger lowers the effective stroke length of the plunger in the pump barrel.
Currently the most efficient form of down-hole gas separation is provided by a packer type separation system that forces all reservoir fluids into the casing-tubing annulus to utilize the larger cross-section of the annulus to reduce velocities of the liquid and, thereby, allow the gas to separate from the liquids. The packer is used instead of the tubing anchor for securing the tubing to the casing and, since the reservoir fluids enter the casing-tubing annulus above the packer, there are no restrictions on the reservoir fluids and gas to flow as is the case with the tubing anchor. However, one limitation of packer type separation systems is that solids are also introduced into the casing annulus which can settle on top of the packer, potentially causing the packer to become stuck in the wellbore. A stuck packer may require an expensive work-over should the packer need to be removed from the wellbore.
What is needed is a comprehensive system that provides superior gas and solid separation and allows for higher production rates. Additionally, a need exists for a separation system that will work in small diameter casing, including sizes on the order of 4½ inches (11.43 cm).
There is also a need for a packer type gas and solids separation system with higher liquid throughput that will trap solids before they enter or settle out on down-hole equipment.